1. Field of the Invention
The field of invention relates to a spacer fluid composition and method of use. More specifically, the field relates to a composition and method of using a spacer fluid that is compatible with both oil-based fluids and water-based fluids simultaneously.
2. Description of the Related Art
Well Bore, Tubular and Fluid Conduit
A well bore is a hole that extends from the surface to a location below the surface. The well bore can permit access as a pathway between the surface and a hydrocarbon-bearing formation. The well bore, defined and bound along its operative length by a well bore wall, extends from a proximate end at the surface, through the subsurface, and into the hydrocarbon-bearing formation, where it terminates at a distal well bore face. The well bore forms a pathway capable of permitting both fluid and apparatus to traverse between the surface and the hydrocarbon-bearing formation.
Besides defining the void volume of the well bore, the well bore wall also acts as the interface through which fluid can transition between the interior of the well bore and the formations through which the well bore traverses. The well bore wall can be unlined (that is, bare rock or formation) to permit such interaction with the formation or lined (that is, with casing, tubing, production liner or cement) so as to not permit such interactions.
The well bore usually contains at least a portion of at least one fluid conduit that links the interior of the well bore to the surface. Examples of such fluid conduits include casing, liners, pipes, tubes, coiled tubing and mechanical structures with interior voids. A fluid conduit connected to the surface is capable of permitting regulated fluid flow and access between equipment on the surface and the interior of the well bore. Example equipment connected at the surface to the fluid conduit includes pipelines, tanks, pumps, compressors and flares. The fluid conduit is sometimes large enough to permit introduction and removal of mechanical devices, including tools, drill strings, sensors and instruments, into and out of the interior of the well bore.
The fluid conduit made from a tubular usually has at least two openings—typically on opposing ends—with an enclosing surface having an interior and exterior surface. The interior surface acts to define the bounds of the fluid conduit. Examples of tubulars and portions of tubulars used in the well bore as fluid conduits or for making or extending fluid conduits include casing, production liners, coiled tubing, pipe segments and pipe strings. An assembly of several smaller tubulars connected to one another, such as joined pipe segments or casing, can form a tubular that acts as a fluid conduit.
When positioning a tubular or a portion of tubular in the well bore, the volume between the exterior surfaces of the fluid conduit or tubular portion and the well bore wall of the well bore forms and defines a well bore annulus. The well bore annulus has a volume in between the external surface of the tubular or fluid conduit and the well bore wall.
Well Bore Fluid
The well bore contains well bore fluid from the first moment of formation until completion and production. The well bore fluid serves several purposes, including well control (hydraulic pressure against the fluids in the hydrocarbon-bearing formation), well bore wall integrity (hydraulic pressure on the well bore wall; provides loss control additives) and lubricity (operating machinery). Well bore fluid is in fluid contact with all portions of and everything in the well bore not fluidly isolated, including the tubular internal fluid conduit, the well bore annulus and the well bore wall. Other fluid conduits coupled to the well bore often contain at least some well bore fluid.
While drilling, drilling fluid (“mud”) fills the interior of the well bore as the well bore fluid. Some muds are petroleum-based materials and some are water-based materials. Petroleum-based materials comprise at least 90 weight percent of an oil-based mud (OBM). Examples of suitable base petroleum materials include crude oils, distilled fractions of crude oil, including diesel oil, kerosene and mineral oil, and heavy petroleum refinery liquid residues. A minor part of the OBM is typically water or an aqueous solution that resides internally in the continuous petroleum phase. Other OBM components can include emulsifiers, wetting agents and other additives that give desirable physical properties.
Oil-based muds also include synthetic oil-based muds (SOBMs). Synthetic oil-based muds are crude oil derivatives that have been chemically treated, altered or and refined to enhance certain chemical or physical properties. In comparison to a crude temperature fraction of a partially-refined crude oil, which may contain several classes (for example, alkane, aromatic, sulfur-bearing, nitrogen-bearing) of thousands of individual compounds, a SOBM can comprise one class with only tens of individual compounds (for example, esters compounds in a C8-14 range). Examples of materials used as base fluids for SOBMs include linear alpha olefins, isomerized olefins, poly alpha olefins, linear alkyl benzenes and vegetable and hydrocarbon-derived ester compounds. SOBMs are monolithic systems that behave in a manner as if they were an oil-based mud but provide a more narrow and predictable range of chemical and physical behaviors.
While performing drilling operations, well bore fluid circulates between the surface and the well bore interior through fluid conduits. Well bore fluid also circulates around the interior of the well bore. The introduction of drilling fluid into the well bore through a first fluid conduit at pressure induces the motivation for the fluid flow in the well bore fluid. Displacing well bore fluid through a second fluid conduit connected to the surface causes well bore fluid circulation from the first fluid conduit to the second fluid conduit in the interior of the well bore. The expected amount of well bore fluid displaced and returned to the surface through the second fluid conduit is equivalent to the amount introduced into the well bore through the first fluid conduit. Parts of the well bore that are fluidly isolated do not support circulation.
Drilling muds that are not water based tend to dehydrate and lose additives during drilling operations. Dehydrated and additive-poor residues can collect in lower-flow velocity parts as solids, gels and highly viscous fluids. “Filter cake” is a layer of deposited solids and gelled drilling fluid that adheres to the interior surfaces of the well bore, including the well bore wall and the exterior of the fluid conduit.
Cementing the Well Bore
Cementing is one of the most important operations in both drilling and completion of the well bore. Primary cementing occurs at least once to secure a portion of the fluid conduit between the well bore interior and the surface to the well bore wall of the well bore.
A variety of water-based cements slurries is available for primary cementing operations. Primary cements typically contain calcium, aluminum, silicon, oxygen, iron and sulfur compounds that react, set and harden upon the addition of water. The water used with the cement slurry can be fresh water or salt water and depend on the formation of the cement slurry and its tolerance to salts and free ions. Suitable water-based cements include Portland cements, pozzolana cements, gypsum cements, high alumina content cements, slag cements, silica cements, high alkalinity cements, latex and resin-based cements. Cement slurries useful primary cementing operations meet the standards given by the American Petroleum Institute (API) in Specification 10A for classes A-H.
Primary cementing forms a protective solid sheath around the exterior surface of the introduced fluid conduit by positioning cement slurry in the well bore annulus. Upon positioning the fluid conduit in a desirable location in the well bore, introducing cement slurry into the well bore fills at least a portion if not all of the well bore annulus. When the cement slurry cures, the cement physically and chemically bonds with both the exterior surface of the fluid conduit and the well bore wall, coupling the two. In addition, the solid cement provides a physical barrier that prohibits gases and liquids from migrating from one side of the solid cement to the other via the well bore annulus. This fluid isolation does not permit fluid migration uphole of the solid cement through the well bore annulus.
Displacing well bore fluid for primary cementing operations is similar to establishing circulation in the well bore fluid with a drilling mud. An amount of cement slurry introduced into the well bore through a first fluid conduit induces fluid flow in the well bore and displaces an equivalent amount of well bore fluid to the surface through a second fluid conduit. In such an instance, the well bore fluid includes a portion of the well bore fluid previously contained in the well bore before cement introduction as well as the amount of the introduced cement slurry.
Cementing in the presence of filter cake can cause a cementing job to fail. The adhesion of filter cake and gelled fluid to the well bore wall or the tubular exterior is weak compared to the bond that cement can make. Cementing on top of filter cake strips the cake off the walls and exterior surfaces due to the weight of the cement upon curing. This lack of direct adhesion creates fluid gaps in and permits circulation through the well bore annulus.
Incompatible Fluid Interaction
Direct contact between the water-based cement slurry and the oil-based drilling mud can result in detrimental fluid interactions that can jeopardize not only cementing operations but also the integrity of the well bore. The intermingling of incompatible fluids can create emulsions (both water-in-oil and oil-in-water emulsions) between the fluids. The emulsions, which resist fluid movement upon the application of force, raises the viscosity profile of the well bore fluid. Increasing pumping head pressure to maintain a constant fluid circulation rate in the well bore can result in damaging the formation downhole as well bore fluid pressure exceeds the fracture gradient of the formation.
Besides detrimentally affecting the viscosity profile, when solids and water from the cement slurry transfer into the oil-based drilling mud during emulsification, the oil-based mud properties are detrimentally affected. Dilution, chemical interaction, breaking of a water-in-oil emulsion and flocculation of suspended additives out of the oil phase can also occur.
Cement slurry properties can also suffer from contamination by the OBM. Flocculation of weighting agents and macromolecules can cause the cement to have reduced compressive strength. The diffusion of ionic species from the OBM can cause premature setting of the cement slurry. The ramifications of early cement hardening include equipment damage, time delay, well bore damage and possible loss of the entire tubular string. Contamination of the cement slurry with bulk OBM results in higher slurry viscosity and higher fluid losses from the hardening slurry.